EP0291750A2

EP0291750A2 - A method for transmitting tool face orientation data in a reduced time

Info

Publication number: EP0291750A2
Application number: EP88106955A
Authority: EP
Inventors: Rainer Dr. Jürgens
Original assignee: Eastman Christensen Co; Eastman Teleco Co
Current assignee: Baker Hughes Oilfield Operations LLC
Priority date: 1987-05-04
Filing date: 1988-04-30
Publication date: 1988-11-23
Also published as: US4873522A; EP0291750A3; CA1287142C

Abstract

A tool face orientation of a directional drill bit within a borehole is efficiently communicated to the well surface by communicating only changes in the tool face orientation. In the first embodiment after the entire tool face orientation is measured and transmitted uphole, and thereafter changes of the tool face orientation as measured with respect to the center of spatially fixed sectorial ranges are transmitted uphole. The magnitude of the changes relative to the center of a fixed sectorial range, being smaller than the range of the entire tool face orientation, allow the subsequent transmission to be made using words of shorter length. Alternatively, the changes in tool face orientation may be measured with respect to a sliding reference point. The sliding reference point may, for example, be the mean value of the prior ten measurements and any previous mean values. The sliding sector will then be held until change in the tool face orientation cause the tool to go out of the sectorial range of the sliding reference point, at which point a new sliding reference is defined which inherently includes the tool face within its range.

Description

Background of the invention

The invention relates to the field of earth boring tools and more particularly to methodologies for transmitting tool face orientation data within a bore hole.
In order to successfully operate a directional drill it is necessary to know the orientation of the drill bit downhole at all times.The orientation, or angular position of the tool face downhole is sensed by a downhole mechanism, such as gravitational or magnetic sensors and then transmitted to the well platform where the directional drilling procedure is controlled. Transmission is typically through mud pulsing which is relatively slow, particularly compared to electronic communication rates, so that there is a premium placed upon efficiency of the downhole communication technique. In one prior art tool, borehole orientation is communicated uphole in forty-eight bits of information transmitted in straight serial binary form at one second intervals, LICHTE, Jr. et al., "Borehole Orientation Tool", U.S. Patent 3,771,118 (1973).
The tool face orientation is generally described in angular coordinates, such as borehole inclination and azimuth. Therefore, a plurality of parameters must be transmitted in order to obtain a complete characterization of tool orientation. See, for example, ARMISTEAD, "Borehole Directional Logging", U.S. Patent 3,691,363 (1972).
Therefore, what is needed is a transmission protocol whereby tool face orientation may be efficiently transmitted to the well surface in a manner which is not subject to the defects of the prior art, and which may be transmitted in reduced time.
The invention is a method for reducing transmission time of tool face orientation data in a borehole comprising the steps of transmitting the entire tool face orientation with a communicated word of a fixed bit length, storing the entire tool face orientation, and defining an angular sector and a reference point within the sector for each parameter of the tool face orientation. The method continues with the step of subsequently transmitting tool face orientation within the defined angular sector with a subset of bits of the fixed bit length word to indicate orientation of the tool face within the defined sector relative to the reference point within the sector. As a result, data transmission rates are substantially reduced.
The method further comprises the step of updating the entire tool face orientation when the tool whithin the borehole is out of range as determined by the defined angular sector, and repeating the steps of storing, defining and subsequently transmitting about a newly defined angular sector.
In one embodiment in the step of defining the angular sector, the angular sector is defined about a fixed angular reference point.
In another embodiment in the step of defining the angular sector, the angular sector is defined about a computed angular reference point.
The computed angular reference point is defined as the mean value of a predetermined number of prior tool face orientation measurements and the previously determined defined computed angular reference point.
In still another embodiment the step of defining the computed angular reference point, the computed angular reference point is defined as the prior measurement of the entire tool face orientation.
In the step of transmitting the entire tool face orientation, the tool face orientation is transmitted in an eight-bit word. The first three bits of the eight-bit word defines a predetermined fixed angular sector and the remaining five bits of the eight-bit word are reserved for a signed angular displacement from the angular center of the predetermined angular sector. Therefore, in the step of subsequently transmitting the tool face orientation, only the five-bit portion of the word is transmitted.
In another embodiment in the step of transmitting the entire tool face orientation, the fixed bit length word is an eight-bit word, and in the step of subsequently transmitting the changes in tool face orien tation, four bits of the eight-bit word are transmitted as a signed angular change about the center of the defined angular sector.
In one embodiment in the step of defining the sectorial range, the angular sector is defined about a sliding reference point.
In the one embodiment in the step of defining, the sliding reference point is defined as the mean value of a predetermined number of prior tool face orientation measurements and the previously determined defined sliding reference point.
In another embodiment in the step of defining the sliding reference point, the sliding reference point is defined as the prior measurement of the tool face orientation.
The invention is also characterized as a method for compressing data for transmission of tool face orientations within an earth boring tool positioned downhole within a borehole. The method comprises the steps of measuring a complete downhole tool face orientation. The complete tool face orientation is transmitted uphole. The complete tool face orientation is stored. Only changes in tool face orientation from a calculated measure of the complete tool face orientation is subsequently transmitted. The complete tool face orientation is periodically measured. The steps of transmitting the complete tool face orientation, storing the tool face orientation and subsequently transmitting only changes from a measure of the tool face orientation are repeated. As a result, data com pression rates are increased.
The invention and its various embodiments are symbolically depicted in the Tables reproduced below and can better be visualized by turning to the following detailed description.
Figure 1 is a graphic depiction of the fixed sector solution of the invention in which the range of an angular parameter, taken in the example of Figure 1 as 0 to 360 degrees, is divided into fixed sectors of 45 degrees each, with the sector designated by a 3-bit number and the point within the sector designated by a 5-bit binary number.
Figure 2 is a graphic depiction of an alternative embodiment of the invention described below as the sliding sector embodiment wherein a predetermined average of an angular parameter of the tool bit orientation is first designated by an 8-bit binary number and thereafter deviations from that predetermined measure or average are designated by a 4-bit binary number.
A tool face orientation of a directional drill bit within a borehole is efficiently communicated to the well surface by communicating only changes in the tool face orientation. In the first embodiment after the entire tool face orientation is measured and transmitted uphole, and thereafter changes of the tool face orientation as measured with respect to the center of spatially fixed sectorial ranges are transmitted up hole. The magnitude of the changes relative to the center of a fixed sectorial range, being smaller than the range of the entire tool face orientation, allow the subsequent transmission to be made using words of shorter length. Alternatively, the changes in tool face orientation may be measured with respect to a sliding reference point. The sliding reference point may, for example, be the mean value of the prior ten measurements and any previous mean values. The sliding sector will then be held until change in the tool face orientation cause the tool to go out of the sectorial range of the sliding reference point, at which point a new sliding reference is defined which inherently includes the tool face within its range.
The efficiency of the transmission rate of tool face data is increased by pulsing only changes in the tool face orientation. In the illustrated embodiments, the data changes are transmitted according to a fixed sector solution in the first embodiment, a sliding sector solution as described in a second embodiment, and last measured value solution in a third embodiment.
Consider first the fixed sector solution as diagrammatically depicted in Figure 1 where the measured angle of one of the tool face orientation angular parameters is symbolically denoted by an X on a circular segment between 45 and 90 degrees. The possible range of an angular tool face orientation is, of course, measured by an angular magnitude between 0 and 360 degrees. Certain ones of the angular parameters, such as inclination, would of course be confined to smaller ranges, e.g. 0 - 180 degrees. In any case the range of the angular parameter can be divided into a plurality of fixed sectors. For example, a range of 360 degrees can be divided into eight fixed sectors, namely 0-45 degrees, 45-90 degrees, 90-135 degrees, and so forth.
The first transmission includes pulses, which are transmitted by whichever means may be employed, such as mud pulsing, electrical communication or other means now known or later devised, in which the entire tool face orientation for the complete magnitude of each tool face parameter is transmitted. There is of course at this step no efficiency or savings in time. Generally, the pulses will comprise a binary word or words, and each binary word will be comprised of eight bits. Eight bits provides in a 360-degree range a signed angular resolution of plus or minus 2.8 degrees. In other words, an sign bit and seven additional bits can represent a change in a parameter of plus or minus 2.8 degrees.
According to the invention, of the eight bits, three bits are used to define one of the eight sectors in which the tool face is oriented. The remaining five bits are reserved for providing the magnitude of the parameter in the designated sector. Thus, as shown in Table 1 below, the eight-bit word is divided into coded fields so that bits, b8-b6, designate the selected 45-degree sector while bits, b5-b1, designate the angular value of the parameter within the designated sector.
On the inital transmission the designated sector is stored in the memory downhole as well as in the surface control unit. It is now possible for the surfasce control unit and the downhole tool to communicate only in terms of values within the designated sector. In other words communication may thereafter proceed on the basis of transmission of a five-bit word.
At that point, when the tool face moves to an orientation so that it is no longer within the same designated sector, the complete eight-bit value of the word is again transmitted and stored at the well surface and downhole.
The methodology of the first embodiment provides, for example, a 62.5% compression of the data transmission time as compared to transmission with standard eight-bit words. However, when the tool face is close to a sector border and changes in a manner such that the tool face is moving back and forth across the sector boundary, the efficiency of the transmission protocol is substantially degraded since the full eight-bit word must be retransmitted on each occasion that the fixed sector border is crossed.
This disadvantage is avoided by practice of the methodology as described below in connection with the second embodiment which is called the sliding sector solution as graphically and symbolically depicted in Figure 2 wherein an actually measured angle of a tool face orientation angular parameter is designated as an X on a circular segment offset from a predetermined measure or average denoted by a dotted line.
As with the first communication protocol, on the first transmission, the entire value of the tool face orientation is transmitted. However, this value is chosen always to be the mean value of a predetermined number of prior measurements. In the illustrated embodiment the initial transmission is the mean value of the first ten tool face orientation measurements. The full mean value of the first ten measurements is now stored in the well surface controller and in the downhole memory. Thereafter, a smaller number of bits is used to describe a sector centered on the mean value. In the illustrated ebodiment four bits are used to describe a sector which ranges from plus or minus 21 degrees on each side of the mean value. Table 2 below illustrates the field encoding for each word utilized in the sliding sector solution. In other words, all eight bits are used to communicate the full mean value and only the last four bits are then later reserved for the signed parametric magnitude.
Tool orientations continue to be communicated using the four bits as long as the tool is within the plus or minus 21 degree range of the initial mean value. When the tool is out of range, a new mean value is computed. In the illustrated embodiment, the new mean value is the average of the last ten measurements within the sector plus the old mean value. Many other choices could be utilized to calculate the new mean value without departing from the spirit and scope of the invention. The choice presently illustrated provides a practical selection based upon the rate of change of tool face orientation typically encountered in petroleum directional drilling.
Alternatively, instead of transmitting the angular orientation of the parameter with respect to a calculated sliding mean value, it is also possible according to the invention to transmit only the change in the actual tool face orientation for each parameter as compared to the last measured tool face value. In each case the reference angle, which was previously held fixed at a computed mean value until the tool face was out of range within the predetermined sector, is re-chosen on each measurement as the last measured tool face orientation. This is called an instantaneous sector solution. The angular reference point is effectively changed through deductive computation on each measurement. In such a case the tool face will as a pratical matter never be out of sector range and theoretically the complete tool face orientation need not ever be transmitted again.
However, due to measurement errors in the orientational equipment as well as in the lack of infinitely precise resolution due to the use of a data word of finite bit length, it is necessary to periodically retransmit the entire tool face orientation for recon firmation or adjustment. In the illustrated embodiment regardless of whether a fixed sector solution, sliding sector solution or an instantaneous sector solution is utilized the entire tool face orientation is retransmitted at least every ten minutes.
Many modifications and alterations may be made by those having ordinary skill in the art without departing from the spirit and scope of the present invention. The illustrated embodiments should therefore be understood as set forth only for the purpose of example and should not be taken as limiting the invention as defined in the following claims.

Claims

1. A method for reducing transmission time of downhole data in a borehole comprising the steps of:
transmitting the entire downhole data with a communicated word of a fixed bit length;
storing said entire downhole data;
defining data sector and a reference point within said data sector for each parameter of said downhole data; and
subsequently transmitting downhole data within said defined data sector with a subset of data bits of said fixed bit length word to indicate the value of said downhole data within said defined data sector relative to said reference point within said data sector,
whereby data transmission rates are substantially reduced.

2. The method of Claim 1 further comprising the step of updating said entire downhole data when said tool within said borehole is out of range as determined by said defined data sector, and repeating said steps of storing, defining and subsequently transmitting about a newly defined data sector.

3. The method of Claim 1 where in said step of defining said data sector, said data sector is defined about a fixed data reference point.

4. The method of Claim 1 where in said step of defining said data sector, said data sector is defined about a computed data reference point.

5. The method of Claim 4 wherein said computed data reference point is defined as the mean value of a predetermined number of prior downhole data measurements and the previously determined defined computed data reference point.

6. The method of Claim 4 where in said step of defining said computed data reference point, said computed data reference point is defined as the prior measurement of said entire downhole data.

7. The method of Claim 3 further comprising the step of updating said entire downhole data when said tool within said borehole is out of range as determined by said defined data sector, and repeating said steps of storing, defining and subsequently transmitting about a newly defined data sector.

8. The method of Claim 4 further comprising the step of updating said entire downhole data when said tool within said borehole is out of range as determined by said defined data sector, and repeating said steps of storing, defining and subsequently transmitting about a newly defined angular sector.

9. The method of Claim 5 further comprising the step of updating said entire downhole data wherein said tool within said borehole is out of range as determined by said defined sectorial data subrange, and repeating said steps of storing, defining and subsequently transmitting but a newly defined sectorial data range.

10. The method of Claim 6 further comprising the step of updating said entire when said tool within said borehole is out of range as determined by said defined data sector, and repeating said steps of storing, defining and subsequently transmitting about a newly defined data sector.

11. The method of Claim 1 where in said step of transmitting said entire downhole data, said downhole data is transmitted in an eight-bit word, the first three bits of said eight-bit word defining a predetermined fixed data sector and the remaining five bits of said eight-bit word reserved to a signed data displacement from the arithmetic mean of said predetermined data sector, and where in said step of subsequently transmitting said downhole data, only said five-bit portion of said word is transmitted.

12. The method of Claim 1 where in said step of transmitting said entire downhole data, said fixed bit length word is an eight-bit word and where in said step of subsequently transmitting said changes in downhole data four bits of said eight-bit word are transmitted as a signed angular change about the arithmetic mean of said defined data sector.

13. The method of Claim 12 where in said step of defining said sectorial data range, said data sector is defined about a sliding reference point.

14. The method of Claim 13 where in said step of defining, said sliding reference point is defined as the mean value of a predetermined number of prior downhole data measurements and the previously determined defined sliding reference point.

15. The method of Claim 13 where in said step of defining said sliding reference point, said sliding reference point is defined as the prior measurement of said downhole data.

16. A method for compressing data for transmission of downhole data from an earth boring tool positioned downhole within a borehole, comprising the steps of:
making a complete downhole measurement of downhole data ;
transmitting said complete downhole data uphole;
storing said complete downhole data;
subsequently transmitting only changes in downhole data from a calculated measure of said complete downhole data; and
periodically measuring said complete downhole data and repeating said steps of transmitting said complete downhole data, storing said downhole data and subsequently transmitting only changes from a measure of said downhole data,
whereby data compression rates are increased.

17. The method of Claim 16 where said changes from said measure of said downhole data is a relative measure of downhole data with respect to a predetermined data reference point within a fixed sectorial data range.

18. The method of Claim 16 where in said step of subsequently transmitting only changes from a measure of said downhole data, said change is a deviation of said downhole data from a sliding mean value of said downhole data.

19. The method of Claim 18 where in said step of subsequently transmitting only changes from a measure of downhole data, said change from said measure is the deviation of the downhole data from a data reference point within a predetermined data sector, said method further comprising the step of redefining said data reference point, said redefined data reference point being a function of said remeasured complete downhole data.

20. The method of Claim 19 where in said step of redefining said reference point, said reference point is redefined by defining said reference point as a mean value of a predetermined number of prior measurements of said complete downhole data and the prior mean value of such downhole data, if any.